CALGARY, Feb. 6, 2012 /CNW Telbec/ - Exall Energy Corporation ("Exall"
or the "Company") (TSX: EE) is pleased to announce the results of its
independent third party NI 51-101 compliant reserves assessment.
Exall's public filings can all be found at www.exall.com or www.sedar.com.

Reserve life index of 4.9 years total proved and 11.0 years proved plus
probable based on the 2011 annual average production rate and year-end
reserves

3D Seismic drilling success promts January 31, 2012 reserves update

2011 Reserve Report

Exall retained AJM / Deloitte Petroleum Consultants ("AJM") to conduct
an independent evaluation of Exall's oil and gas reserves effective
December 31, 2011, which was provided to Exall in an Evaluation Report
dated February 2, 2012 (herein referred to as the "AJM Evaluation").
The oil and gas reserves and income projections were estimated by AJM
in accordance with the Canadian Oil and Gas Handbook ("COGEH") and
National Instrument 51-101 ("NI 51-101").

Summary of Reserve Value - Forecast Pricing

The following tables, extracted from the AJM Evaluation, summarize the
Corporation's total reserves and net present values of future net
reserves based on forecast pricing and costs as at December 31, 2011.
It should not be assumed that the estimated future net cash flow shown
below is representative of the fair market value of the Company's
properties. There is no assurance that such price and cost assumptions
will be attained and variances, both positive and negative, could be
material.

Light &

Natural

Company Gross Reserves(1)

medium oil

gas

NGL

Total

as at December 31, 2011

(Mbbl)

(MMcf)

(Mbbl)

(Mboe)

Proved developed producing

1,800.0

970.2

24.6

1,986.3

Proved developed non-producing

0.0

0.0

0.0

0.0

Proved undeveloped

18.8

224.4

5.7

62.0

Total proved

1,818.8

1,194.6

30.3

2,048.3

Probable

2,390.6

705.9

17.9

2,526.2

Total proved plus probable

4,209.5

1,900.6

48.2

4,574.5

(1) Columns and rows may not add due to rounding

Before Income Tax

Forecast Net Revenue(1)

$000s, discounted at

as at December 31, 2011

0%

5%

10%

15%

Proved developed producing

92,708.9

82,730.4

74,951.1

68,732.4

Proved developed non-producing

0.0

0.0

0.0

0.0

Proved undeveloped

2,292.5

1,443.6

972.3

685.9

Total proved

95,001.4

84,174.0

75,923.4

69,418.3

Probable

126,739.9

105,953.0

91,189.5

80,154.4

Total proved plus probable

221,741.4

190,127.0

167,113.0

149,572.7

(1) Columns and rows may not add due to rounding

After Income Tax

Forecast Net Revenue(1)

$000s, discounted at

as at December 31, 2011

0%

5%

10%

15%

Proved developed producing

84,051.5

74,877.6

67,760.3

62,094.3

Proved developed non-producing

0.0

0.0

0.0

0.0

Proved undeveloped

1,980.7

1,201.8

780.8

531.5

Total proved

86,032.1

76,079.4

68,541.1

62,625.8

Probable

95,648.6

79,363.0

67,891.3

59,363.5

Total proved plus probable

181,680.7

155,442.4

136,432.4

121,989.3

(1) Columns and rows may not add due to rounding

Summary of Forecast Pricing

Future prices used in the forecast of net revenue are based on those
estimated by AJM as at December 31, 2011. The following table sets
forth the relevant portions of AJM's forecast of commodity prices and
costs used in the AJM Evaluation:

Natural Gas Liquids

Year

WTI Crude Oil ($US/BBL)

EdmontonCity Gate ($CDN/BBL)

Natural Gas at AECO ($CDN/MCF)

Edm. Propane ($CDN/BBL)

Edm. Butane ($CDN/BBL)

Edm. C5+ ($CDN/BBL)

Currency Exchange Rate ($US/CDN)

Price Inflation Rate (%)

Cost Inflation Rate (%)

2012

100.00

98.00

3.50

53.90

83.30

102.90

1.00

0.0

0.0

2013

102.00

100.00

4.10

55.00

85.00

105.00

1.00

2.0

2.0

2014

104.05

102.00

4.70

56.10

86.70

107.10

1.00

2.0

2.0

2015

106.10

104.00

5.15

57.20

88.40

109.20

1.00

2.0

2.0

2016

108.25

106.10

5.55

58.35

90.20

111.40

1.00

2.0

2.0

2017

110.40

108.20

6.00

59.50

91.95

113.60

1.00

2.0

2.0

2018

112.60

110.35

6.40

60.70

93.80

115.85

1.00

2.0

2.0

2019

114.85

112.55

6.90

61.90

95.65

118.20

1.00

2.0

2.0

2020

117.15

114.80

7.40

63.15

97.60

120.55

1.00

2.0

2.0

2021

119.50

117.10

7.75

64.40

99.55

122.95

1.00

2.0

2.0

2022

121.90

119.45

7.90

65.70

101.55

125.40

1.00

2.0

2.0

2023

124.35

121.85

8.10

67.00

103.55

127.95

1.00

2.0

2.0

2024

126.80

124.30

8.25

68.35

105.65

130.50

1.00

2.0

2.0

2025

129.35

126.75

8.40

69.70

107.75

133.10

1.00

2.0

2.0

2026

131.95

129.30

8.60

71.10

109.90

135.75

1.00

2.0

2.0

2027

134.60

131.90

8.75

72.55

112.10

138.50

1.00

2.0

2.0

2028

137.30

134.55

8.90

74.00

114.35

141.30

1.00

2.0

2.0

2029

140.00

137.20

9.10

75.45

116.60

144.05

1.00

2.0

2.0

2030

142.80

139.95

9.30

76.95

118.95

146.95

1.00

2.0

2.0

2031

145.70

142.75

9.45

78.50

121.35

149.90

1.00

2.0

2.0

2032
+

2.0 %
escalated

2.0 %
escalated

2.0 %
escalated

2.0 %
escalated

2.0 %
escalated

2.0%
escalated

1.00

2.0

2.0

Reserve Reconciliation

Light &

Natural

Reserve Reconciliation(1)

medium oil

gas

NGL

Total

(Company Working Interest)

(Mstb)

(MMcf)

(Mstb)

(Mboe)

Proved

December 31, 2010

1,864.0

1,264.4

18.5

2,093.2

Extensions & improved recovery

489.7

71.0

1.8

503.3

Technical revisions

(183.7)

104.6

16.2

(150.1)

Economic Factors

0.0

0.0

0.0

0.0

Acquisitions

0.0

0.0

0.0

0.0

Dispositions

0.0

0.0

0.0

0.0

Production

(351.2)

(245.3)

(6.2)

(398.3)

December 31, 2011

1,818.8

1,194.6

30.3

2,048.3

(1) Columns and rows may not add due to rounding

Light &

Natural

Reserve Reconciliation(1)

medium oil

gas

NGL

Total

(Company Working Interest)

(Mstb)

(MMcf)

(Mstb)

(Mboe)

Probable

December 31, 2010

1,029.3

717.1

11.1

1,159.9

Extensions & improved recovery

1,631.0

65.4

1.6

1643.5

Technical revisions

(269.7)

(76.5)

5.2

(277.3)

Economic Factors

0.0

0.0

0.0

0.0

Acquisitions

0.0

0.0

0.0

0.0

Dispositions

0.0

0.0

0.0

0.0

Production

0.0

0.0

0.0

0.0

December 31, 2011

2,390.6

705.9

17.9

2,526.2

Proved plus Probable

December 31, 2010

2,893.3

1,981.4

29.6

3,253.1

Extensions & improved recovery

2,120.7

136.4

3.4

2,146.8

Technical revisions

(453.3)

28.1

21.4

(427.2)

Economic Factors

0.0

0.0

0.0

0.0

Acquisitions

0.0

0.0

0.0

0.0

Dispositions

0.0

0.0

0.0

0.0

Production

(351.2)

(245.3)

(6.2)

(398.3)

December 31, 2011

4,209.5

1,900.6

48.2

4,574.5

(1) Columns and rows may not add due to rounding

2012 Reserve Update

Exall has retained AJM / Deloite Petroleum Consultants ("AJM") to
conduct an independent evaluation of Exall's oil and gas reserves
effective January 31, 2012, as a result of the drilling success
associated with the 3D Seismic well announced January 18th, 2012. The results of this well were not included in the AJM
Evaluation's Total Proved reserves as the well had not been on
production by December 31, 2011, per NI 51-101 requirements. This well
represents 389 MBOE of Total Proved plus Probable Reserves with a 10%
NPV Before Tax value of $18.4 million. It is anticipated that the
inclusion of this well in the Total Proved reserves as of January 31,
2012 will additionally move two Probable locations to the Proved
Undeveloped catagory.

Sale of Texas Gas Properties

Exall has completed the sale of all of its interest in the Harris and
Layton, Texas properties held by the Company to a private American
company. The properties previously produced approximately 40 MCFPD of
gas and associated liquids net to Exall.

About Exall

Exall is a junior oil and gas company active in its business of oil and
gas exploration, development and production from its properties in
Alberta. Exall Energy is currently developing the new Mitsue area
Marten Mountain discovery in north-central Alberta.

Exall Energy currently has 62,263,854 common shares outstanding. The
Company's common shares are listed on the Toronto Stock Exchange under
the trading symbol EE.

Reader Advisory

This news release contains forward-looking statements, which are subject
to certain risks, uncertainties and assumptions, including those
relating to results of operations and financial condition, capital
spending, financing sources, commodity prices and costs of production.
By their nature, forward-looking statements are subject to numerous
risks and uncertainties that could significantly affect anticipated
results in the future and, accordingly, actual results may differ
materially from those predicted. A number of factors could cause actual
results to differ materially from the results discussed in such
statements, and there is no assurance that actual results will be
consistent with them. Such factors include fluctuating commodity
prices, capital spending and costs of production, and other factors
described in the Company's most recent Annual Information Form under
the heading "Risk Factors" which has been filed electronically by means
of the System for Electronic Document Analysis and Retrieval ("SEDAR")
located at www.sedar.com. Such forward-looking statements are made as at the date of this news
release, and the Company assumes no obligation to update or revise
them, either publicly or otherwise, to reflect new events, information
or circumstances, except as may be required under applicable securities
law.

For the purposes of calculating unit costs, natural gas has been
converted to a barrel of oil equivalent (boe) using 6,000 cubic feet
equal to one barrel (6:1), unless otherwise stated. The boe conversion
ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion
method and does not represent a value equivalency; therefore boe may be
misleading if used in isolation. This conversion conforms to the
Canadian Securities Regulators' National Instrument 51-101 - Standards
of Disclosure for Oil and Gas Activities.